Page 1648 – RTO Insider

March 11, 2014

Exelon in Lobbying Push to Save Ill. Nukes

By Ted Caddell

Lobbyists from Exelon Corp. have descended on Illinois lawmakers, warning that current energy prices and renewable energy subsidies could force them to shut down three nuclear stations in the state.

“If we do not see a long-term path to sustainable profitability for a particular unit, then we will consider all options available to us, including unit shutdowns,” reads a memo that is part of a presentation lobbyists are using. “We are looking for solutions, and we are talking about this now both to let you know what we are up against, and to avoid any surprises later.”

The presentation does not name any particular plants in Exelon Nuclear’s six-plant Illinois fleet, but one consultant in the state energy industry said the Exelon lobbyists are naming the Quad Cities, Clinton and Byron plants as those most at risk.

Taken together, the three stations generate 5,243 MW, employ 2,300, have an annual payroll of $193 million and pay more than $51 million in taxes.

That consultant, who asked not to be named, said Exelon was using industry-wide figures, and not plant-specific financials, in their briefings.

“It is not clear to me whether these plants are losing money, or just not making enough money,” he said.

All Illinois Plants Unprofitable?

According to an analysis by the Chicago Tribune, all six of the plants in Exelon’s Illinois nuclear fleet have been unprofitable over the past five years. The Tribune examined hourly power prices and plant production and concluded that all six plants failed to meet capital and operational costs since 2008.

Exelon spokesman Paul Adams last week confirmed that the company had held “informational” meetings with lawmakers but wouldn’t answer specific questions about plant profitability or discuss which legislators participated. “The company has not asked lawmakers for a fix,” he said.

In a prepared statement, Exelon said that while it hasn’t targeted any plants for closure, the prospect was not unthinkable.

“We have no current plans to close any of our nuclear units prior to the end of their federally licensed operating lives, with the exception of Oyster Creek [in New Jersey], which we’ve agreed to close in 2019,” the company said. “That said, the combined effect of low wholesale power prices and the unintended consequences of current energy policies is challenging the economics of several of Exelon’s Illinois nuclear units.”

It added, “It is too soon to discuss specifics and the company has not asked Illinois officials to provide a state remedy for the current market conditions affecting nuclear plants.”

CEO Chris Crane told analysts in an earnings call in February that the company’s nuclear stations, especially in the Midwest, were getting squeezed by low energy prices, as well as competition from subsidized renewables and low-cost natural gas generation. (See Exelon May Close Nukes.)

Presentation

Exelon lobbyists are using a 20-page presentation outlining what they say are conditions that threaten the profitability of its nuclear generating stations in Illinois.

Byron Generating Station (Source: Exelon) — Chart from Exelon PowerPoint to Illinois Legislature: Impact on Carbon Goals (Source: Exelon)

“Some of our plants, particularly in Illinois, face severe economic headwinds because of low power prices and the unintended consequences of current energy policies, and it is not certain that we will be able to run them much longer,” one part of the presentation reads. “We have one plant that leads the nation in virtually every operational, safety and reliability category. Yet it cannot consistently earn a profit.”

The presentation doesn’t identify that plant, but it seems to be a reference to the Byron Generating Station, a two-reactor, 2,346-MW plant that had a 96.2% capacity factor in 2013 — the highest among the Illinois plants and the second highest in its entire fleet. (Limerick Nuclear Generating Station, in Londonderry Township, Pa., came in first with 96.3%.) Byron’s net generation for the year was 19.5 million MWh, eclipsed only by the Braidwood station.

Clinton Generating Station’s 2013 capacity factor was the lowest in Exelon’s fleet, at 87.7%.

Exelon has asked the Nuclear Regulatory Commission to extend the licenses of the Byron plant — due to expire in 2024 and 2026 — by 20 years.

Grand Prairie

While Exelon is telling some lawmakers that Byron may be targeted for shut down, just three months ago sister company Commonwealth Edison filed a proposal with the Illinois Commerce Commission to build a 60-mile transmission line from Byron station to Wayne, Ill., just west of Chicago.

The 345 kV Grand Prairie Gateway Project, which has already won PJM’s approval, would provide a third west-to-east transmission line across ComEd’s territory, relieving transmission congestion across northern Illinois.

ComEd spokesman David O’Dowd said Friday that the Grand Prairie transmission line is still considered a high-priority project. Pending ICC approval, the project should be completed by 2017, the company said.

Analyst Reaction

In a presentation to PJM’s General Session in February, Julien Dumoulin-Smith, a utility analyst at UBS Securities LLC in New York, noted that Exelon’s Quad Cities plant went from running at zero hours of negative pricing in 2006 to 101 hours of negative pricing in 2013, with an average negative price of $15.35 per MWh. Quad Cities’ average LMP price plummeted from $41.02 in 2006 to $25.36 in 2013.

“I think Exelon is dead serious,” Dumoulin-Smith told Crain’s Chicago Business last week. “Their willingness to withstand losses is going to be tested if they don’t do something.”

According to the Tribune analysis, the Quad Cities and Byron plants experienced negative pricing 8% and 7%, respectively, of their operating hours during 2012.

Carbon Price

The presentation left with lawmakers cites the rising role of low-cost natural gas-fired generation, renewable subsidies and transmission constraints. It also cites the lack of a federal price on carbon, which would improve nuclear’s competitiveness against gas and coal.

“Renewables are important, however, the subsidies they receive are an unfair factor that make it difficult for Nuclear to be competitive in the same market place,” one slide says.

“Energy policy frameworks in the U.S. do not compensate nuclear energy either for its carbon-free output or its unrivaled reliability,” it goes on. “Unless we fix that gap, the U.S. is going to lose nuclear plants. We need more emission-free electricity in Illinois and the U.S., not less. Getting rid of the cheapest, most reliable source of electricity in America today makes no sense.”

The current lobbying push, according to the Illinois energy consultant, is conditioning.

“Right now, they are just laying the groundwork by telling everybody they have a problem,” he said. “It is like tenderizing meat. And then, we’ll see when the solution presents itself, or when the solution is presented by them.”

March 11, 2014

PJM Won’t Act Alone on Black Start

PJM won’t seek additional compensation for black start generators in the face of stakeholder opposition, officials told members Friday. Instead, members of the task force studying the issue will be polled to determine their next step.

Two proposals that would have boosted payments to existing units failed to win a two-thirds vote from stakeholders Feb. 27 as the Markets and Reliability Committee split along supply-load fault lines. (See Stakeholders Reject Pay Hike for Black Start Units.)

Some stakeholders contend existing black start generators should receive additional compensation to encourage them to continue providing the service.

But PJM Executive Vice President for Operations Mike Kormos told the System Restoration Strategy Task Force Friday that the Board of Managers will not act unilaterally on any pay increase because there is no evidence that the current compensation is causing an exodus.

“They don’t see a reliability concern,” Kormos said. “Quite frankly, the equity issues are not that clear.”

He added, “That’s not to say [the board’s view] won’t change. That’s why I’m hesitant to say cut the discussion off.”

One proposal, which would have increased annual payments for a 20 MW CT to $71,600, from the current $51,000, won only 60% support in the MRC vote. An alternative, which would have boosted compensation for the same unit to $312,500, also fell short, with only 45% support.

Task force chair Chantal Hendrzak said she will send a poll to task force members March 12 to determine next steps. Hendrzak said the poll will seek to gauge sentiment for reevaluating a PJM proposal considered by the task force, which would have boosted pay for a 20 MW CT to $65,000.

The poll also will ask about a narrower proposal that would not change the base compensation but would broaden the units that could receive compensation.

It would allow:

compensation for storage of fuel other than oil;
automatic load rejection units — plants that can disconnect from the grid during a blackout — to recover the costs of complying with NERC cybersecurity standards; and
energy-only units to receive compensation.

One member representing a generation owner expressed doubt that the work would be productive. “I don’t think loads are going to vote for anything [that increases compensation],” said AEP’s Brock Ondayko.

March 11, 2014

Company Briefs

Public Service Enterprise Group chairman and CEO Ralph Izzo doesn’t see the electric industry moving to a largely distributed-generation future. The utility network is the most efficient way to provide power, Izzo said in an E&E TV interview. But energy efficiency should be paramount, he said, and he sees the utility of the future as an energy services provider. “I would like to see us expand way beyond the meter to be someone who provides energy services that help customers lower their bills, first and foremost,” Izzo said. “Secondly, to the extent that people still require electricity – because even though you use less of it, you still will require it – we’re the most reliable provider of that electricity possible.”

Izzo also discussed PSE&G’s $3.9 billion Energy Strong effort and described “a whole host of problems” with the Federal Energy Regulatory Commission’s Order 1000 on transmission planning and cost allocation.

More: E&E TV

PSE&G Workers Hurt, Woman Killed in NJ Gas Explosion

Fire officials in Ewing Township, N.J. said they were not informed of a gas leak before an explosion that killed a resident and injured seven PSE&G workers March 4. Two townhomes were obliterated and 55 others were damaged by the explosion and fire, many so badly they will have to be razed.

A PSE&G crew had been summoned to the townhouse development after a contractor reported hitting a gas line while performing electrical repairs. The utility workers had been at the scene for about 45 minutes when the explosion occurred.

Fire officials said they would have evacuated the area had they been informed of the leak. The New Jersey Board of Public Utilities is investigating the actions of PSE&G and the contractor. The board can levy fines if state regulations were violated. The Occupational Health and Safety Administration (OSHA) is also investigating.

More: NJ.com; PSE&G

PSEG Sets $12B Capital Spending Over 5 Years

Public Service Enterprise Group will spend about $12 billion in capital investments, mainly in transmission, over the next five years. The operating utility, Public Service Electric and Gas, will spend $10 billion over that time, 20% more than the previous five years, mostly for PJM-mandated transmission upgrades to relieve projected system overloads and maintain reliability, PSEG announced at its annual investor conference in New York City.

This year, operating earnings from the regulated business will be about 55% of earnings, Chairman and CEO Ralph Izzo said, and the utility’s capital spending program will lead to double-digit earnings growth over the 2013-2016 period.

More: PSEG

March 11, 2014

Residential Demand Response Initiative Moves Forward

The Market Implementation Committee approved an issue charge directing the Demand Response Subcommittee to consider ways to allow residential customers to participate in the synchronized reserve market through demand response.

The MIC approved a problem statement on the topic last month. (See Members to Review Rules on Residential DR, SR Market.)

Comverge’s Frank Lacey, sponsor of the initiative, said residential DR will only be economical as a synchronized reserve resource if members approve an alternative to one-minute direct metering, which can cost upwards of $1,500 per unit.

Dave Pratzon, of GT Power Group, said that after discussions with Lacey he was satisfied that “not metering certain customers would be appropriate if the customers are very homogenous in nature so that DR response is going to be [predictable].”

Another question the subcommittee will consider is whether to limit eligibility to direct load-controlled properties.

March 11, 2014

PPL Announces SPS for Susquehanna-Jenkins

PPL announced a special protection scheme to prevent overloads on its Susquehanna-Jenkins 230 kV transmission line.

According to PPL’s presentation to the Planning Committee last week, the protection would be activated under NERC N-1-1 contingencies, for example the loss of both the Susquehanna-Lackawanna 500 kV line and Mountain-Lackawanna 230 kV lines.

The scheme would trip the Stanton #1 and #2 breakers at Jenkins five minutes after the Susquehanna-Jenkins line exceeds 100% of its emergency rating and one minute after it exceeds its loadshed rating.

The scheme will be removed following the rebuild of Susquehanna-Jenkins (RTEP project b2269), which is scheduled for completion in summer 2018.

March 11, 2014

Planners Begin Work on Market Efficiency Window

PJM will conduct training April 17 for transmission developers who want to submit proposals in the RTO’s second “market efficiency” window in November. The session will educate developers on how PJM calculates the benefits of improvements to reduce transmission congestion.

PJM officials acknowledged the need for training after selecting only one of 17 proposals submitted in the first market efficiency window last year. It was a disappointing beginning for those who had hoped FERC Order 1000 would unleash competition in transmission development. (See PJM to OK Only 1 of 17 Congestion Relief Proposals.)

Five of the projects were rejected because the congestion developers targeted had been addressed by other transmission projects or generation, while another nine projects failed to clear the 1.25 benefit-to-cost threshold.

Three projects passed the cost-effectiveness screen, but because they all addressed congestion in the same area, only one proposal was approved.

At last week’s Transmission Expansion Advisory Committee meeting, PJM officials outlined the data and assumptions that will be used to identify areas of the grid that could benefit from “economic” upgrades.

The assumptions are to be finalized by May, with preliminary results from the congestion analysis in June. After incorporating stakeholder feedback on the model, PJM will open the proposal window in November.

March 11, 2014

PJM: Con Ed Protest over PSEG Upgrade Groundless

PJM told the Federal Energy Regulatory Commission last week that it should reject an attempt by Consolidated Edison Co. to avoid paying for more than half of a $1.2 billion transmission upgrade to address a short circuit problem in the PSE&G transmission zone outside New York City.

The project, part of PJM’s Regional Transmission Expansion Plan (RTEP), will convert Public Service Electric and Gas Co.’s Bergen-to-Linden 138 and 230 kV transmission line to 345 kV and add a second 345 kV transmission line between those points. (See Planners Choose $1.2B PSEG Short Circuit Fix.)

$629 Million Allocation

Cost Allocation for PSEG Short Circuit Fix (Source: Con Edison) — (Source: Con Edison)

Con Edison says PJM’s cost allocation unfairly assigns $629 million of the cost to it as a result of the Con Ed-PSEG “wheel,” in which PSEG takes 1,000 MW from Con Ed at the New York border and delivers it to Con Ed load in New York City. Its protest was joined by the New York Public Service Commission and New York City (ER14-972).

PJM told FERC in an answer filed Friday that Con Ed’s protest is a challenge to the distribution factor (DFAX) cost allocation method outlined in Schedule 12 of PJM’s Open Access Transmission Tariff and approved by FERC in Order 1000 proceedings.

If Con Ed’s challenge prevailed, PJM said, “Every project would be open to project-by-project subjective ad hoc determinations of `beneficiaries,’ which the [Order 1000] cost allocation process is designed to avoid.”

Regional Benefits or Local Reliability Fix?

The dispute could turn on whether the commission agrees with PJM that the PSE&G upgrade has regional benefits, as PJM insists, or whether it primarily addresses a local reliability problem, as the protestors contend.

Under rules approved by FERC last year (142 FERC ¶ 61,214), PJM will allocate the cost of regional projects — defined as double 345kV and those 500kV and above — under a hybrid formula: Half of the cost is socialized based on load share and the other half based on identified beneficiaries. PJM previously allocated the cost of regional upgrades solely on load share. (See PJM TOs’ ROFR Bid Rejected; “Hybrid” Cost Allocation Plan Approved.)

For reliability projects, the beneficiaries are identified based on post-upgrade load flow, as determined by a DFAX analysis.

In approving the use of DFAX, the commission ordered PJM and its transmission owners to provide more detail regarding how the formula would be implemented. “While PJM has adequately shown how the DFAX values and usage of transmission facilities will be calculated, there is no detail regarding how these values will be utilized to calculate assignments of cost responsibility,” the commission said.

The PJM Transmission Owners responded with a compliance filing in July. The commission has not ruled on the filing.

Jan. 10 Filing

On Jan. 10, PJM submitted to FERC amendments to Schedule 12 of its Tariff reflecting cost responsibility for 111 baseline RTEP upgrades approved by the Board of Managers in December.

PSEG Short Circuit Solution (Source: PJM Interconnection, LLC)

The filing said the “PSEG Northern NJ 345 kV Project” (project b2436) is intended to relieve overdutied breakers at Essex, Kearny, and NJ Meadowlands 230kV.

In the Transmission Expansion Advisory Committee’s recommendation to the Board, PJM said the $1.2 billion project would also allow cancellation of previously approved RTEP projects totaling $1.04 billion. Thus, the additional work had an incremental cost of only $160 million, PJM said.

The hybrid formula was applied to 15 of the 26 subprojects that comprise the PSE&G upgrade. Of the remaining 11 subprojects, one is fully allocated to PSE&G and the remaining 10 are allocated based on DFAX, according to Con Ed.

According to Con Ed’s calculations, almost $763 million of the project cost will be assigned based on DFAX calculations, with the remaining $418 million allocated based on load ratio shares.

Con Ed-PSEG Wheel

The Con Ed-PSEG wheel began in the 1970s as a grandfathered service by PSE&G, and was converted in 2012 to the PJM Tariff.

Con Edison says RTEP charges currently represent about $9 million of the wheel’s $40 million annual cost. The $600 million allocation for the short circuit fix would quadruple the cost of the wheel to $160 million annually, Con Ed says. “While Con Edison continues to find value in the service that the Commission approved as important to regional reliability, irrational increases in costs could ultimately undermine this arrangement,” it said.

Con Ed says it was unfairly assessed almost 83% of the $762.6 million assigned through DFAX for its 1,000 MW wheel while PSE&G was assessed only 7%, despite load of 11,000 MW. Con Ed said the cost distribution for the project — which contends the upgrade would be needed without its wheel — is “grossly disproportionate to the relative loads” of the two companies.

Linden Challenge

After Con Ed filed its challenge, Linden VFT LLC, a subsidiary of General Electric Capital Corp., filed a protest of its own. Linden VFT, which owns a 315 MW merchant transmission facility which interconnects both PJM and NYISO, said it learned from the Con Ed challenge that it would be billed an additional $2.5 million in RTEP charges annually, more than doubling its current RTEP tab.

LindenVFT Variable Frequency Transformer (Source: LIndenVFT)

“It is simply inaccurate to allocate to Linden VFT these costs based on likely power flows over the PSE&G Upgrade when the PSE&G Upgrade will be built to resolve short circuit fault currents, not to accommodate additional power flows,” Linden said.

“PJM has chosen to apply the rules applicable to double circuit 345 kV transmission lines versus those for circuit breakers that would more appropriately reflect what is happening,” Linden said. “As a result, rather than bearing the entire cost of the PSE&G Upgrade, the PSE&G zone would avoid almost 94% of the portion of the project cost that is allocated using DFAX.”

In addition, Linden complains, the allocation makes no adjustment for the benefits received by customers who would have been assessed the costs of the previously approved RTEP projects that were cancelled as a result of the PSE&G upgrade.

Linden filed its protest Feb. 27, 17 days after comments were due. Linden said it should be permitted the late filing because the Con Ed protest “identified new issues that should have been identified in PJM’s January 10 filing.”

PJM responded that “the PSE&G Upgrade solves more than local short circuit issues and is properly treated as a Regional Facility.”

“Linden VFT’s objections are challenges to the justness and reasonableness of the cost allocation process set forth in the PJM Tariff, which are beyond the scope of this proceeding,” it added.

March 11, 2014

PC Starts Work on Small Generator Interconnection Changes

The Planning Committee voted last week to initiate work to bring PJM into compliance with the Federal Energy Regulatory Commission’s Small Generator Interconnection rules.

FERC Order 792, issued in November, streamlines interconnection procedures for small generators connecting to transmission at 69 kV and below. (See Rule Set for Small Generators.)

The PC approved a problem statement that will lead to changes in PJM’s Small Generator Interconnection Procedures and Small Generator Interconnection Agreement.

John Brodbeck of Pepco Holdings Inc. said he hoped the changes PJM makes will accommodate Pepco’s proposed alternative to pre-application and fast-track screening, which he said is more appropriate for testing renewable generation’s impact on system reliability.

Pepco has told FERC that it has developed a modeling tool that can determine a maximum allowable hosting capacity at a given point of interconnection.

“As we move through the process, I fear we’re going to [endorse] a process for all of PJM even if we believe we have an alternative that’s more appropriate for our territories,” said Brodbeck.

PJM must make a compliance filing by Aug. 3.

March 11, 2014

Winter Testing May Be on the Horizon

By David Jwanier

Nearing the end of one of the harshest winters in its history, PJM is considering requiring cold-weather testing of generators, officials told the Operating Committee last week.

Generation Outages by Unit Type (Source: PJM Interconnection, LLC)

During the polar vortex in early January, forced outages downed as much as 20% percent of PJM’s generation, including almost one-third of combustion turbines and diesel units. Operators had to resort to demand response and a voltage reduction to keep the grid functioning. Generator failures dropped to more typical rates of 8% to 10% later in the month.

The early January failure rate was the worst PJM has experienced since 1994, according to a “frequently asked questions” report on the January cold released last week. PJM, then only consisting of the MAAC region, saw rotating blackouts for several hours during the 1994 “Deep Freeze.”

Executive Director of System Operations Mike Bryson said the high initial failure rate has officials considering rules to require winter start tests for generators. Reintroducing winter capacity tests is also under consideration, he said.

Winter testing would “give GOs the opportunity to test units that don’t ordinarily start or that are using alternative fuels,” he said. “I’m less worried about capacity.”

Among the issues that stakeholders will need to discuss are the timing of the tests and compensation for generation operators. “You don’t want to start too early because that doesn’t replicate the cold weather,” said Bryson, who suggested the checks could be conducted between Thanksgiving and the end of December. Waiting until January, he said, “sort of defeats the purpose.”

One stakeholder suggested installing heaters on units and that providing additional staffing could help reliability but added that those costs aren’t recoverable.

Although the North American Electric Reliability Corp. may eventually issue cold weather reliability standards, Bryson said PJM should move to institute its own requirements by the fall.

“I don’t want to do nothing for next year,” Bryson said.

March 11, 2014

CFTC Giving Trader Data to FERC; Turf Issues Remain

By Kathy Larsen

The Commodity Futures Trading Commission has begun regular information-sharing with the Federal Energy Regulatory Commission after several years of wrangling and pressure from the Senate to make good on promises of cooperation.

The CFTC is now sending FERC its Large Trader Report on a routine basis so FERC will not have to request it case-by-case for market surveillance.

The sharing, which followed memorandums of understanding the agency heads signed in January, is a milestone in the government’s efforts to police market manipulation. But conflicts over the two agencies’ jurisdiction are still being played out in court.

As the commissions announced their initial data-sharing last week, they also announced establishment of a staff-level Interagency Surveillance and Data Analytics Working Group to coordinate the sharing “and focus on data security, data-sharing infrastructure and the use of analytical tools for regulatory purposes.”

Last month, eight senators leaned on the CFTC to make good on the sharing promised in the Jan. 2 MOUs, which were required by the 2010 Dodd-Frank law.

Sen. Dianne Feinstein (D-Calif.), who has pressed the agencies more than once for action, last week commended them for starting the “overdue” sharing. “FERC investigators have caught multiple entities manipulating California’s markets in recent years – even without access to this critical data,” she said. “I am hopeful the trading data … will allow FERC to prevent the complex and sophisticated schemes that robbed consumers and disrupted economic activity during the Western energy crisis.”

One of the January MOUs outlined a process by which the commissions would notify each other of activities that may involve overlapping jurisdiction, and when entities request authorization or exemptions that may fall in that overlap. The other MOU established processes for sharing information of mutual interest.

The eight senators who wrote to the CFTC Feb. 10 said they were impatient that no concrete action had taken place yet because of what the CFTC had said were data transfer issues.

“Considering the CFTC’s technical ability to share data with other nations and other regulators,” the senators wrote to CFTC acting Chairman Mark Wetjen, “we believe that technical barriers preventing the sharing of information with FERC — a fellow arm of the federal government — could be addressed and solved in a matter of weeks under your direction and leadership.” The trader-report sharing came a few weeks later.

The CFTC has not yet asked for access to FERC data on an ongoing basis.

Questions surrounding the exchange of information are only part of the conflict that has characterized the commissions’ relationship. FERC lost a fight to pursue a market manipulation case against Brian Hunter, of hedge fund Amaranth Advisors, when the U.S. Court of Appeals for the District of Columbia Circuit ruled the CFTC had exclusive jurisdiction over the matter.

FERC has continued to assert its jurisdiction, however, particularly in the power arena. Last year it ordered Barclays Bank PLC to pay $470 million in fines and disgorged profits for allegedly manipulating California’s power markets.

The bank challenged FERC’s authority, saying the agency lacks jurisdiction over transactions that involve futures and swaps and do not involve actual physical transmission or delivery of power.

The case is pending before the U.S. District Court for the Eastern District of California (FERC v. Barclays Bank PLC et al., Case No. 2:13-cv-02093-TLN-DAD).

Attorneys at Bracewell & Giuliani said the case’s “resolution may significantly affect the scope of FERC’s enforcement authority going forward.”

The commission seems to agree. In a filing in February, FERC said that a ruling in Barclays’ favor would “eviscerate the regulation of wholesale electricity markets contemplated” in the Federal Power Act.